Electrical equipment, particularly medium-voltage or high-voltage devices, requires a high degree of electrical and thermal insulation between components thereof. Accordingly, it is well known to encapsulate components of electrical equipment, such as coils of a transformer, in a containment vessel and to fill the containment vessel with a fluid. The fluid facilitates dissipation of heat generated by the components and can be circulated through a heat exchanger to efficiently lower the operating temperature of the components. The fluid also serves as electrical insulation between components or to supplement other forms of insulation disposed around the components, such as cellulose paper or other insulating materials. Any fluid having the desired electrical and thermal properties can be used. Typically, electrical equipment is filled with oil, such as castor oil, mineral oil, or vegetable oil, or synthetic “oil”, such as chlorinated biphenyl or silicone.
Often, electrical equipment is used in a mission-critical environment in which failure can be very expensive, or even catastrophic, because of a loss of electric power to critical systems. In addition, failure of electrical equipment ordinarily results in a great deal of damage to the equipment itself and surrounding equipment, thus requiring replacement of expensive equipment. Further, such failure can cause injury to personnel due to electric shock, fire, or explosion. Therefore, it is desirable to monitor the status of electrical equipment to predict potential failure of the equipment through detection of incipient faults and to take remedial action through repair, replacement, or adjustment of operating conditions of the equipment. Faults and incipient faults should be distinguished from normal and acceptable degradation. However, the performance and behavior of fluid-filled electrical equipment inherently degrades over time. Transformer oil cools the transformer and acts as a dielectric. As transformer oil ages it becomes a less effective dielectric. Oil condition also is affected by the condition of other active components in the electrical equipment with which it is in intimate contact.
A method of monitoring the status of fluid-filled electrical equipment is to monitor various parameters of the fluid. For example, the temperature of the fluid and the total combustible gas (TCG) in the fluid is known to be indicative of the operating state of fluid-filled electrical equipment. Therefore, monitoring these parameters of the fluid can provide an indication of any incipient faults in the equipment. For example, it has been found that carbon monoxide and carbon dioxide increase in concentration with thermal aging and degradation of cellulosic insulation in electrical equipment. Hydrogen and various hydrocarbons (and derivatives thereof such as acetylene and ethylene) increase in concentration due to hot spots caused by circulating currents and dielectric breakdown such as corona and arcing. Concentrations of oxygen and nitrogen indicate the quality of the gas pressurizing system employed in large equipment, such as transformers. The measurement of certain gases, such as hydrogen, acetylene, methane, ethane, and ethylene in the oil of an electrical transformer is of interest as it is an indication of the breakdown of the oil caused by overheating and/or arcing inside the transformer. The increase in hydrogen, for example, dissolved in the transformer oil is an indicator of the coming failure of the transformer. Accordingly, “dissolved gas analysis” (DGA) has become a well-accepted method of discerning incipient faults in fluid-filled electric equipment.
In conventional DGA methods, an amount of fluid is removed from the containment vessel of the equipment through a drain or other fluid sampling valve. The removed fluid is then subjected to testing for dissolved gas in a lab or by equipment in the field. This method of testing is referred to herein as “offline” DGA. Since the gases are generated by various known faults, such as degradation of insulation material or other portions of electric components in the equipment, turn-to-turn shorts in coils, overloading, loose connections, or the like, various diagnostic theories have been developed for correlating the quantities of various gases in fluid with particular faults in electrical equipment in which the fluid is contained. If analysis is conducted off site, results may not be obtained for several hours. Incipient faults may develop into failure of the equipment over such a period of time.
Often it is neither practical nor desirable to conduct offline DGA analyses frequently enough to detect incipient faults rapidly enough to take remedial action in a timely manner. Such sampling and testing requires deployment of personnel to a remote site of the monitored electrical asset, which often involves significant time and travel. Customary offline DGA testing intervals range from weeks to years in duration.
Accordingly, in order to acquire DGA analysis results more frequently for critical electrical assets, devices for DGA analysis directly at the transformer have been deployed. Such analysis systems, termed “online” DGA analyzers, are connected directly to the fluid tank of a transformer via a sealed circulation loop. The dielectric fluid flows directly from and back to the tank. This arrangement has the advantage that errors from manual oil sampling are eliminated; fault gases are not lost from the sample during sampling, transport, and lab analysis, and the fault gas content of the oil sample is preserved. The time between oil sample acquisition and analysis in an online system is a matter of minutes, compared to hours or days for offline DGA testing.
Online DGA analyzers utilize a number of analytical chemical technologies including gas chromatography (GC), infrared (IR) spectroscopy, and solid-state sensors. Chromatographic and spectroscopic sensing systems generally require a gas-phase sample from the dielectric fluid, while solid-sensors may respond to a gas-phase sample or directly to gases dissolved in the oil.
Unfortunately, in a spectroscopic gas sensor for process gas analysis, including DGA, the presence of some commonly found matrix gases, such as propane and propylene, interfere with measurement of the analyte gases such as methane, ethane, and ethylene. The interferences arise when the selected radiation wavelengths of the spectroscopic sensor are absorbed by both analyte and matrix gases in common. The interference results in significantly higher sensor readings than the true analyte gas levels, which degrades analyte gas measurement accuracy and repeatability.
Devices such as the GE-Kelman Transfix and related online spectroscopic DGA monitors attempt to address the above problems. In particular, such devices extract dissolved gases from electrical insulating fluids for subsequent analysis. The problem of matrix gas interference is addressed by measuring the aggregate contribution of the interfering and analyte gases together followed by removal of the analyte gases from the contained gas and oil volumes by sparging the oil volume with ambient air and releasing the gases to an outside vent. The analyte gases are less soluble in the oil and are sparged out more rapidly than are the more soluble interfering matrix gases, which are retained preferentially inside the oil volume.
A series of gas-sensor readings is made as the analyte gases are sparged, preferentially from the system wherein the matrix gas concentrations decrease more slowly than the analyte gas concentrations. Ultimately only a small fraction of the analyte gases remain in the system such that the gas sensor measures the fractional remaining analyte gases plus the much larger fraction of remaining matrix gases. Finally, an estimate is calculated of the difference between the gas sensor reading with and without the interfering matrix gases by curve-fitting and extrapolation towards the eventual sensor readings with zero remaining analyte gases and fractional remaining matrix gases. This difference is taken as the sensor reading as if no matrix gases were present.
The rates of removal of the analyte and matrix gases from the electrical insulating fluid sample are primarily a function of their solubility in the fluid. Unfortunately, site-to-site and time-based variations in the chemical nature of the fluid preclude exact knowledge of the degree of partial removal of the gases from the fluid. Subtraction of the extrapolated value of the matrix-gas-only sensor response from the initial full-sample sensor response incurs a large error as well. These uncertainties degrade the ultimate accuracy and repeatability of the analytical results.
In addition, higher molecular weight substances are present in electrical insulating oil, such as hexanes, heptanes, octanes, and so on up to carbon numbers in excess of C40 and higher in the case of mineral insulating oil. At normal oil operating temperatures from 20 to 100° C. the more volatile of these oil components will partially vaporize. The vaporized oil matrix substances may then condense on sufficiently cool surfaces to which they are exposed, as in for example the gas paths leading to a spectroscopic sensor and inside the sensor itself. Having condensed in the active spectroscopic sensing area, these less volatile, condensed matrix compounds can interfere with the measurement of the analyte gases in much the same way as gaseous matrix components.
Existing on-line DGA devices achieve some remediation of condensing matrix vapors by establishing and maintaining a positive thermal gradient between the bulk oil sample temperature and the gas analyzer. In this manner, accumulation of condensable matrix compounds may be minimized but not entirely eliminated.